Systems for determining at least one condition proximate the system

ABSTRACT

Sensing systems include a tube defining a Fabry-Perot cavity and an optical fiber including a distal end disposed within the Fabry-Perot cavity and a proximal end. A corrodible material caps the Fabry-Perot cavity. Devices for sensing corrosion of downhole equipment include an optical fiber with a corrodible material disposed over a distal end of the optical fiber. Systems for sensing a condition in equipment include an optical fiber with a fiber Bragg grating proximate a distal end thereof and a mass of sensor material coupled to the distal end of the optical fiber. The mass of sensor material is suspended from above the fiber Bragg grating. Other systems for sensing a condition in a wellbore include an optical fiber and a plurality of fiber Bragg gratings along a length thereof. A plurality of sensor materials are coupled to the optical fiber and surround respective fiber Bragg gratings.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. patent application Ser. No.16/452,044, filed Jun. 25, 2019, which is a divisional of U.S. patentapplication Ser. No. 15/387,110, filed Dec. 21, 2016, now U.S. Pat. No.10,371,502, issued Aug. 6, 2019, which is a divisional of U.S. patentapplication Ser. No. 14/319,158, filed Jun. 30, 2014, now U.S. Pat. No.9,562,844, issued Feb. 7, 2017, the disclosure of each of which ishereby incorporated herein in its entirety by this reference.

FIELD

Embodiments of the present disclosure relate to systems and devices forsensing corrosion and deposition in equipment for the exploration andproduction of oil and gas, including, without limitation, corrosion oftools and tool components and deposition of scale on tools and toolcomponents used in wellbores and surface equipment.

BACKGROUND

Tools and instruments used for oil and gas exploration and productionare often exposed to corrosive conditions, such as high temperatures,high pressures, reactive chemicals, and abrasive materials. Therefore,these tools corrode and degrade during use. In addition, scale (i.e.,debris and materials from the wellbore or from fluids therein) may bedeposited on tools used for exploration and production of oil and gas,which may foul the operation of the tools and create a flow restriction.Fiber optic sensors have several advantages over electro-mechanicalsensors: they exhibit greater resistance to aggressive environments,exhibit a smaller footprint with single-point or multi-pointmeasurements, exhibit immunity to electromagnetic noise, and are moreresistant to mechanical vibration.

BRIEF SUMMARY

In some embodiments, the present disclosure includes wellbore sensingsystems including a tube defining a Fabry-Perot cavity, an opticalfiber, a corrodible material capping the Fabry-Perot cavity, and ananalysis module. The optical fiber includes a distal end disposed withinthe Fabry-Perot cavity and a proximal end opposite the distal end. Theanalysis module is operatively coupled to the proximal end of theoptical fiber, and is configured to sense and analyze a difference of alight signal resulting from a change in a distance between thecorrodible material and the distal end of the optical fiber due to achange in thickness of the corrodible material.

In some embodiments, the present disclosure includes devices for sensingcorrosion of downhole equipment, including at least one optical fibercomprising a distal end and a proximal end. The devices also include acorrodible material disposed over the distal end of the at least oneoptical fiber. An analysis module is operatively coupled to the proximalend of the at least one optical fiber. The analysis module is configuredto sense and analyze differences in a light signal reflecting from thecorrodible material.

In some embodiments, the present disclosure includes systems for sensingat least one condition in oil and gas exploration or productionequipment, including at least one optical fiber, an analysis module, anda mass of sensor material. The at least one optical fiber includes adistal end, at least one fiber Bragg grating proximate the distal end,and a proximal end. The analysis module is coupled to the proximal endof the at least one optical fiber, and is configured to sense andanalyze variations in light reflected from the at least one fiber Bragggrating. The mass of sensor material is coupled to the distal end of theat least one optical fiber. At least one surface of the mass of sensormaterial is exposed to an environment surrounding the distal end of theat least one optical fiber. The distal end of the at least one opticalfiber with the mass of sensor material coupled thereto is suspended fromabove the fiber Bragg grating to induce stress on the fiber Bragggrating due to a weight of the mass of sensor material.

In some embodiments, the present disclosure includes devices for sensingdeposition of material on downhole equipment. The devices include atleast one optical fiber comprising a proximal end and a distal endincluding a fiber Bragg grating. An analysis module is operativelycoupled to the proximal end of the at least one optical fiber, and theanalysis module is configured to sense and analyze variations in lightreflected from the at least one fiber Bragg grating. The devices alsoinclude a suspension element coupled to the at least one optical fiberabove the fiber Bragg grating. A mass of inert material is coupled tothe at least one optical fiber below the fiber Bragg grating andsuspended from the suspension element by the distal end of the at leastone optical fiber.

In some embodiments, the present disclosure includes additional systemsfor sensing at least one condition in a subterranean wellbore. Thesystems include at least one optical fiber including a distal end, aplurality of fiber Bragg gratings along a length thereof, and a proximalend. A plurality of sensor materials are coupled to the at least oneoptical fiber and surround respective fiber Bragg gratings of theplurality of fiber Bragg gratings. A light wavelength sensor is coupledto a proximal end of the at least one optical fiber. The lightwavelength sensor is configured to sense a wavelength of light reflectedfrom the plurality of fiber Bragg gratings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates an embodiment of a wellbore sensing system accordingto the present disclosure.

FIG. 2 shows a partial cross-sectional view of an embodiment of a fiberoptic sensor according to the present disclosure.

FIG. 3 shows a partial cross-sectional view of an embodiment of areference fiber optic sensor according to the present disclosure.

FIG. 4 shows a partial side view of an embodiment of a multi-pointsensor according to the present disclosure.

FIG. 5 shows a detailed cross-sectional view of a single sensor of themulti-point sensor of FIG. 4 within the dashed circle A.

FIG. 6 shows a partial side view of an embodiment of a multi-pointreference sensor according to the present disclosure.

FIG. 7A shows a partial cross-sectional side view of another embodimentof a fiber optic sensor according to the present disclosure.

FIG. 7B shows a partial cross-sectional side view of the fiber opticsensor of FIG. 7A under pressure.

FIG. 7C shows a partial cross-sectional side view of the fiber opticsensor of FIG. 7A under pressure and after corrosion thereof.

FIG. 8A shows a partial cross-sectional side view of another embodimentof a fiber optic sensor according to the present disclosure, includingmultiple optical fibers.

FIG. 8B shows an end view of the fiber optic sensor of FIG. 8A, takenfrom line 8B-8B in FIG. 8A.

FIG. 9 shows a partial cross-sectional side view of another embodimentof a fiber optic sensor according to the present disclosure.

FIG. 10A shows a partial cross-sectional side view of another embodimentof a fiber optic sensor according to the present disclosure.

FIG. 10B shows an end view of the fiber optic sensor of FIG. 10A, takenfrom line 10B-10B in FIG. 10A.

DETAILED DESCRIPTION

The following description provides specific details, such as materialtypes, configurations, and operating conditions in order to provide athorough description of embodiments of the present disclosure. However,a person of ordinary skill in the art will understand that theembodiments of the present disclosure may be practiced without employingthese specific details. Indeed, the embodiments of the presentdisclosure may be practiced in conjunction with conventional techniquesand materials employed in the industry.

In the following detailed description, reference is made to theaccompanying drawings, which form a part hereof, and in which is shown,by way of illustration, specific embodiments in which the presentdisclosure may be practiced. These embodiments are described insufficient detail to enable a person of ordinary skill in the art topractice the present disclosure. However, other embodiments may beutilized, and structural, logical, and electrical changes may be madewithout departing from the scope of the disclosure. The illustrationspresented herein are not meant to be actual views of any particularsystem, device, structure, or process, but are idealized representationsthat are employed to describe the embodiments of the present disclosure.The drawings presented herein are not necessarily drawn to scale.

Similar structures or components in the various drawings may retain thesame or similar numbering for the convenience of the reader; however,the similarity in numbering does not mean that the structures orcomponents are necessarily identical in size, composition,configuration, or other property.

As used herein, the term “substantially” in reference to a givenparameter, property, or condition means and includes to a degree thatone skilled in the art would understand that the given parameter,property, or condition is met with a small degree of variance, such aswithin acceptable manufacturing tolerances. For example, a parameterthat is substantially met may be at least about 90% met, at least about95% met, or even at least about 99% met.

As used herein, any relational term, such as “first,” “second,” “over,”“top,” “bottom,” “underlying,” etc., is used for clarity and conveniencein understanding the disclosure and accompanying drawings and does notconnote or depend on any specific preference, orientation, or order,except where the context clearly indicates otherwise.

As used herein, the term “corrosion” means physical and chemicaldegradation.

As used herein, the term “corrodible” in reference to a material meanssusceptible to corrosion in an environment in which the material is tobe placed.

As used herein, the term “distal” refers to a portion of a structure ora location that is relatively more distant from an indicated point ofreference than another portion of a structure or another location.

As used herein, the term “proximal” refers to a portion of a structureor a location that is relatively closer to an indicated point ofreference than another portion of a structure or another location.

The embodiments of the present disclosure include fiber optic sensorsfor sensing corrosion, scale deposition, and the presence of reactivechemicals in harsh environments, such as in wellbores formed in theearth for exploration for and production of hydrocarbons such as oil andnatural gas, as well as exploration for and production of geothermalenergy. In some embodiments, single-point sensors are disclosed.

Referring to FIG. 1, an embodiment of a wellbore sensing system 100 isshown. The wellbore sensing system 100 includes downhole components 102within a wellbore 104. In embodiments in which the wellbore 104 waspreviously formed (e.g., during oil production), the downhole components102 may include production components, such as an electric submersiblepump (“ESP”) 106 and casing 108. In embodiments in which the wellbore104 is being formed (during, e.g., oil exploration or wellboreformation), the downhole components 102 may include earth-boringcomponents, such as a downhole motor, an earth-boring tool, and drillpipe. In either case, the downhole components 102 may be exposed to acorrosive environment including one or more of high temperatures, highpressures, abrasive materials, and reactive chemicals, for example.

The wellbore sensing system 100 may include a sensor including at leastone optical fiber 110 having at least one sensing point 112. Forexample, a single-point sensor may include a single sensing point 112Aat a distal end 114 of the at least one optical fiber 110. By way ofanother example, a multi-point sensor may include a plurality of sensingpoints 112B along a length of the at least one optical fiber 110.Embodiments of both single-point and multi-point sensors will bedescribed in more detail below with reference to FIGS. 2-6.

The wellbore sensing system 100 may include an analysis module 116operably coupled to the at least one optical fiber 110. The analysismodule 116 may be configured to receive and analyze signals in the formof light (e.g., visible light, infrared light, ultraviolet light)reflected and/or refracted from the at least one sensing point 112. Forexample, the analysis module 116 may include a frequency domainreflectometer. Frequency domain reflectometers are commerciallyavailable, such as the “Luna Distributed Sensing System” sold by LunaInnovations Incorporated of Roanoke, Va. U.S. patent application Ser.No. 11/180,389 to Childers et al., titled “FIBER OPTIC POSITION ANDSHAPE SENSING DEVICE AND METHOD RELATING THERETO,” filed on Jul. 13,2005, describes operation of a fiber optic position and shape sensingdevice comprising an optical fiber means. A frequency domainreflectometer is positioned in an operable relationship to the opticalfiber means. The disclosure of U.S. patent application Ser. No.11/180,389 is incorporated in its entirety herein by reference. By wayof other examples, the analysis module 116 may include at least one of alight source, a photodetection and signal processing interferometer, alight wavelength sensor, a light intensity sensor, and an outputconfigured to provide a signal (e.g., an electronic signal, a display,data) corresponding to the metric to be measured (e.g., corrosion rate).

Optionally, one or more reference optical fibers 118 (as shown by dashedline) may be positioned proximate and along the at least one opticalfiber 110 to compensate for changes in temperature, pressure, stress(such as, for example, bending, compressive, tensile, and torsionalstress), vibrations, etc., and to provide a reference signal that can becompared to (e.g., subtracted from) a signal from the at least oneoptical fiber 110 to determine a portion of the signal from the at leastone optical fiber 110 that correlates to the condition to be sensed,independent of other conditions to which the at least one optical fiber110 and the one or more reference optical fibers 118 are exposed. Forexample, U.S. patent application Ser. No. 11/451,207 to Poland et al.,titled “MULTI-CORE DISTRIBUTED TEMPERATURE SENSING FIBER,” filed on Jun.12, 2006, now U.S. Pat. No. 7,379,631, issued May 27, 2008, describes amulti-core distributed temperature sensing optical fiber, wherein thearrangement and construction of at least two cores provides a spectralattenuation corrected (e.g., corrected for hydrogen and/or stress on thefiber) temperature measurement. The disclosure of U.S. Pat. No.7,379,631 is incorporated in its entirety herein by reference.

The wellbore sensing system 100 of the present disclosure may beconfigured to provide a signal relating to, for example, one or more oftemperature, stress, strain, pressure, occurrence of corrosion, rate ofcorrosion, presence of a reactive chemical, and position information atthe at least one sensing point 112, as will be further explained below.

Referring to FIG. 2, wellbore sensing systems of the present disclosuremay include a fiber optic sensor 200 including a fiber Bragg grating 202proximate a distal end 204 of an optical fiber 206 and a mass of sensormaterial 208 coupled to the distal end 204 of the optical fiber 206. Ahousing 210 may cover lateral sides of the mass of sensor material 208,while leaving at least a portion of an end surface 212 of the mass ofsensor material 208 exposed to the surrounding environment. The distalend 204 of the optical fiber 206 and the mass of sensor material 208 maybe suspended from a suspension element 214, such that the fiber Bragggrating 202 is positioned between the suspension element 214 and themass of sensor material 208. The mass of sensor material 208 may berestricted from moving laterally (e.g., to the left and right and intoand out of the page from the perspective of FIG. 2), but not restrictedfrom moving axially (e.g., up and down from the perspective of FIG. 2)by the housing 210. Thus, the weight of the mass of sensor material 208may physically stress (e.g., stretch) the portion of the optical fiber206 including the fiber Bragg grating 202 between the suspension element214 and the mass of sensor material 208.

Optical fibers including fiber Bragg gratings are known in the art andare described in, for example: U.S. patent application Ser. No.09/979,345 to Kraemmer et al., titled “BRAGG GRATING DEVICE FORMEASURING AN ACCELERATION,” issued as U.S. Pat. No. 6,807,325 on Oct.19, 2004; U.S. patent application Ser. No. 11/180,389 to Childers etal., titled “FIBER OPTIC POSITION AND SHAPE SENSING DEVICE AND METHODRELATING THERETO,” filed Jul. 13, 2005; and U.S. patent application Ser.No. 11/451,207 to Poland et al., titled “MULTI-CORE DISTRIBUTEDTEMPERATURE SENSING FIBER,” filed on Jun. 12, 2006; the entiredisclosure of each of which is incorporated herein by reference.

By way of example, the fiber Bragg grating 202 may include a portion ofa core of the optical fiber 206 characterized by periodic variations inrefractive index. The period of the fiber Bragg grating 202 (i.e., thedistance between adjacent portions having variations in refractiveindex) results in reflection and/or refraction of light of a specificwavelength or range of wavelengths correlating to the period of thefiber Bragg grating 202. If the period of the fiber Bragg grating 202 isrelatively larger, then light having a relatively longer wavelength willbe reflected and/or refracted by the fiber Bragg grating 202.Conversely, if the period of the fiber Bragg grating 202 is relativelysmaller, then light having a relatively shorter wavelength will bereflected and/or refracted by the fiber Bragg grating 202. An analysismodule (e.g., the analysis module 116 described above with reference toFIG. 1) operatively coupled to the at least one optical fiber 206 can beused to sense the wavelength of light reflected and/or refracted by thefiber Bragg grating 202. A single fiber Bragg grating 202 may have avariable period (and, therefore, may reflect and/or refract light havinga corresponding variable wavelength) that is dependent on the axialstretching and compressing of the optical fiber 206, which respectivelyincreases and decreases the period of the fiber Bragg grating 202. Axialstretching and compressing of the optical fiber 206 may result from, forexample, changes in temperature of and axial physical stress on theoptical fiber 206.

The fiber optic sensor 200 shown in FIG. 2 may be used to sensecorrosion of the mass of sensor material 208 due to chemical and/orphysical degradation of the end surface 212 of the mass of sensormaterial 208. As material from the mass of sensor material 208 isexposed to a corrosive environment and corroded, the weight of the massof sensor material 208 may be reduced, which may reduce stress on theoptical fiber 206 resulting from the weight of the mass of sensormaterial 208. As a result, the period of the fiber Bragg grating 202 maybe reduced as the stress thereon is relaxed. A signal (e.g., lightreflected and/or refracted) from the fiber Bragg grating 202 may bealtered due to the change in the period of the fiber Bragg grating 202.The signal may be sensed remotely by an analysis module coupled to aproximal end of the optical fiber 206, and the change in the signal maybe correlated to corrosion of the mass of sensor material 208. Thus, thefiber optic sensor 200 may be used to remotely sense corrosion at thedistal end 204 of the optical fiber 206. The fiber optic sensor 200 maybe a single-point sensor for sensing corrosion at a single point withina wellbore (e.g., at a position of the distal end 204 of the opticalfiber 206). In some embodiments, multiple fiber optic sensors 200 may beused within a single wellbore to sense corrosion at multiple pointswithin the wellbore.

In use within a wellbore, the fiber optic sensor 200 may be positionedproximate a downhole component, such as by coupling the housing 210 tothe downhole component or simply by extending the fiber optic sensor 200into the wellbore to the position of the downhole component. Thematerial of the mass of sensor material 208 may include a corrodiblematerial that is selected to have a corrosion rate that is at leastsubstantially the same as a corrosion rate of a material of the downholecomponent. In some embodiments, the material of the mass of sensormaterial 208 may be the same as the material of the downhole component.By way of example and not limitation, the material of the mass of sensormaterial 208 may include one or more of aluminum, titanium, a carbonsteel, a tool steel, a stainless steel, and a so-called“corrosion-resistant alloy.” Corrosion resistant alloys may include, forexample, steels such as those identified in industry as 9 Cr-1 Mo, 13Cr, 13 Cr-2 Mo, 416 stainless steel, 316 stainless steel, and nickelalloys such as those identified in industry as nickel alloy 625, nickelalloy 718, and MONEL® K-500. Thus, corrosion of the mass of sensormaterial 208 that is sensed by the fiber optic sensor 200 may bedirectly correlated to corrosion of the corresponding downholecomponent. The surface area of the mass of sensor material 208 endsurface 212 may be known and used to calculate a corrosion rate of thematerial based on a mass loss over time detected by the fiber opticsensor 200. Thus, the fiber optic sensor 200 may be used to detectoccurrence of corrosion and/or a corrosion rate of the downholecomponent.

In some embodiments, the fiber optic sensor 200 may additionally oralternatively be configured and used to sense deposition of scale on thedownhole component. For example, if the material of the downholecomponent is susceptible to scale deposition, the material of the massof sensor material 208 or a portion thereof may be selected to also besusceptible to scale deposition (e.g., by forming the mass of sensormaterial 208 of the same material as the downhole component). Inoperation, as scale is deposited on the end surface 212 of the mass ofsensor material 208, a combined weight of the mass of sensor material208 and deposited scale increases and induces greater tension on thefiber Bragg grating 202. The increased tension, in turn, increases theperiod of the fiber Bragg grating 202. A corresponding shift inwavelength of reflected and/or refracted light may be sensed andcorrelated to the scale deposition.

The mass of sensor material 208 may be formed of a substantially uniformand homogeneous material, or may be formed of a non-uniform andheterogeneous material. For example, in some embodiments, the mass ofsensor material 208 may be formed of a substrate coupled to the distalend 204 of the optical fiber 206, with a material at least substantiallysimilar to the material of the downhole component coupled to (e.g.,attached to, sputtered on, bonded to, deposited on) the substrate.

The fiber optic sensor 200 of FIG. 2 has been described as including asingle optical fiber 206. However, the present disclosure is not solimited. Rather, in some embodiments, multiple optical fibers 206 may becoupled to the mass of sensor material 208. In such embodiments, themass of sensor material 208 may be larger than would be possible with asingle optical fiber 206 because the multiple optical fibers 206 would,in combination, be capable of holding more weight without breaking.Therefore, the mass of sensor material 208 may include more material tocorrode for longer operational life. In addition, respective signalsfrom the multiple optical fibers 206 may be independently sensed andanalyzed to identify non-uniform corrosion of the mass of sensormaterial 208.

Referring to FIG. 3 in conjunction with FIG. 2, in some embodiments, areference fiber optic sensor 300 may be used with the fiber optic sensor200. The reference fiber optic sensor 300 of FIG. 3 may be similar tothe fiber optic sensor 200 described with reference to FIG. 2, and mayinclude a fiber Bragg grating 302 proximate a distal end 304 of anoptical fiber 306 and a housing 310, at least substantially as describedabove. However, the reference fiber optic sensor 300 may include a massof material 308 with at least an end surface 312 including a materialthat is different from the mass of sensor material 208. For example, themass of sensor material 208 of the fiber optic sensor 200 may be acorrodible material and the mass of material 308 of the reference fiberoptic sensor 300 may be an inert material. By way of example and notlimitation, the inert material may include one or more of a ceramicmaterial, a diamond-like carbon (“DLC”) material, an oxide material, asapphire material, an alumina material, a silicon carbide material, asilicon material, and a metallic material (e.g., corrodible material ormaterial similar to the corrodible material) but with the end surface312 coated with an inert coating, such as DLC. The entire mass ofmaterial 308 of the reference fiber optic sensor 300 may be the inertmaterial, or the end surface 312 of the mass of material 308 may becoated with the inert material. In some embodiments, the mass ofmaterial 308 may include or be coated with a material selected to resistscale deposition, such as a hydrophobic material.

The reference fiber optic sensor 300 may be used to compensate fortemperature, pressure, vibration, and other conditions that may alterthe period of the fiber Bragg gratings 202, 302 during use. For example,both the fiber optic sensor 200 and the reference fiber optic sensor 300may be exposed to the same conditions (e.g., temperature, pressure,vibration), which may induce a substantially similar, if not identical,shift in the period of both of the fiber Bragg gratings 202, 302.However, the mass of sensor material 208 may corrode or experience scaledeposition while the mass of material 308 of the reference fiber opticsensor 300 may not (or may to a lesser degree) corrode or experiencescale deposition. Accordingly, a signal (e.g., light reflecting and/orrefracting) from the reference fiber optic sensor 300 may be compared to(e.g., subtracted from) a signal from the fiber optic sensor 200 toisolate a portion of the fiber optic sensor 200 signal that results froma change in the mass of sensor material 208, independent of temperature,pressure, vibration, and other environmental conditions.

Referring to FIG. 4, a multi-point sensor 400 may include an opticalfiber 402 with multiple sensors 404 along a length thereof. Adjacentsensors 404 may be spaced at intervals D of, for example, at least about5 mm, such as between about 5 mm and about 2 cm, although someembodiments of the present disclosure include sensors 404 at otherintervals. The optical fiber 402 may be positioned in a wellbore tosense downhole conditions (e.g., temperature, pressure, presence ofreactive chemical(s), corrosion rate) at multiple positions within thewellbore.

FIG. 5 illustrates in detail the sensor 404 shown in FIG. 4 withindashed circle A. All of the sensors 404 of the multi-point sensor 400shown in FIG. 4 may be substantially the same as the sensor 404described below with reference to FIG. 5.

As shown in FIG. 5, each sensor 404 may be a portion of the opticalfiber 402 that includes a fiber Bragg grating 406 surrounded by a sensormaterial 408. A cladding material 410 may surround the optical fiber 402adjacent to the sensor material 408.

In some embodiments, the sensor material 408 may be or include acorrodible material, such as a material that is also used for a downholecomponent. The sensor material 408 may be pre-stressed in a manner thatcauses the fiber Bragg grating 406 to be in axial tension orcompression. During use in a corrosive downhole environment, the sensormaterial 408 may corrode at a rate that is substantially the same as acorrosion rate of an exposed surface of a corresponding downholecomponent. As the pre-stressed sensor material 408 corrodes, the stresstherein may relax and a period of the fiber Bragg grating 406 may bealtered. A change in the period of the fiber Bragg grating 406 may besensed and analyzed to determine a corrosion rate, in essentially thesame manner as described above. Signals from each of the sensors 404along the optical fiber 402 (FIG. 4) may be independently sensed andanalyzed to identify localized corrosion.

In some embodiments, the sensor material 408 may be or include amaterial that is selected to sense a presence of a reactive chemicalwithin the wellbore, such as hydrogen sulfide (H₂S), commonly termed“sour gas” in the industry. For example, the sensor material 408 may beselected to chemically react with the reactive chemical of interest. Byway of example and not limitation, in embodiments in which the sensor404 is intended for sensing the presence of H₂S, the sensor material 408may be a metallic oxide material, such as zinc oxide (ZnO), which reactswith H₂S to form zinc sulfide (ZnS) and water (H₂O). The resulting ZnShas a volume that is theoretically about 59.18 times greater than avolume of ZnO. Accordingly, if the sensor material 408 of ZnO is exposedto sufficient H₂S, the sensor material 408 may expand and induce stress(e.g., tension) in the optical fiber 402, effectively stretching andincreasing a period of the corresponding fiber Bragg grating 406. Thus,a signal from the sensor 404 may be remotely sensed and analyzed toidentify the presence and location of H₂S in the wellbore. In thismanner, the multi-point sensor 400 may be used in a wellbore as adetection and warning system to enable identification of reactivechemicals prior to the reactive chemicals reaching a proximal portion ofthe wellbore. If a reactive chemical is sensed and located by themulti-point sensor 400, precautions or remedial action may be taken,such as shutting down production of the wellbore, shutting downproduction of a portion the wellbore, and/or evacuating personnel.

Referring to FIG. 6 in conjunction with FIGS. 4 and 5, in someembodiments, the multi-point sensor 400 may be used with a referenceoptical fiber 602 that is similar to the optical fiber 402 describedabove, except that the sensor material 408 may be replaced by or coatedwith an inert (e.g., non-corrodible, non-reactive) material 608 in thereference optical fiber 602. As with the reference fiber optic sensor300 (FIG. 3), the reference optical fiber 602 may be used to isolateportions of signals relating to the desired variable (e.g., corrosionrate, presence of a reactive chemical) from portions of signalsresulting from other conditions (e.g., temperature, pressure,vibration).

Referring to FIG. 7A, wellbore sensing systems of the present disclosuremay include a fiber optic sensor 700 including a so-called Fabry-Perotcavity 702 at a distal end 704 of at least one optical fiber 706. TheFabry-Perot cavity 702 may be defined by a tube 708 (e.g., a capillarytube) capped with a corrodible material 710 having an external surface712 that is configured for exposure to a corrosive environment, such asan environment within a subterranean wellbore or other fluid systems inoil and gas exploration and production. In some embodiments, an interiorof the Fabry-Perot cavity 702 may be filled with a fluid, such as aliquid (e.g., oil) or a gas. The corrodible material 710 may be selectedto include or be a similar (e.g., same) material as a downhole componentproximate to the distal end of the at least one optical fiber 706, suchthat corrosion of the corrodible material 710 can be directly correlatedto corrosion of the material of the downhole component. By way ofexample and not limitation, the corrodible material 710 may include oneor more of a carbon steel, a tool steel, a stainless steel, and aso-called “corrosion-resistant alloy.”

Extrinsic Fabry-Perot interferometry (EFPI) techniques may be used tomeasure the thickness of thin foils, such as of the corrodible material710. The fiber optic sensor 700 of the present disclosure may operate bymeasuring the intensity and interference of light passing through the atleast one optical fiber 706 and reflecting from the back-end of thecorrodible material 710. As the external surface 712 of the corrodiblematerial 710 is corroded by the corrosive environment to which thecorrodible material 710 is exposed, an initial thickness T of thecorrodible material 710 may diminish under a known pressure gradientacross the corrodible material 710. Change in the thickness T under anapplied pressure P (e.g., a fluid pressure) may cause a change in a gaplength L between the distal end of the at least one optical fiber 706and the back of the membrane, as illustrated in FIGS. 7B and 7C.

As shown in FIGS. 7B and 7C, as a first thickness T₁ of the corrodiblematerial 710 reduces due to corrosion of the external surface 712thereof to a second thickness T₂, the corrodible material 710 may becomeincreasingly curved under the pressure P. The corrosive environment mayhave a relatively higher pressure than an interior of the Fabry-Perotcavity 702, and the net pressure P may cause the corrodible material 710to curve inward toward the at least one optical fiber 706. Thecorrodible material 710 having the first thickness T₁ may be positioneda first distance L₁ from the distal end 704 of the at least one opticalfiber 706 under the pressure P (FIG. 7B). As the corrodible material 710corrodes, the thickness of the corrodible material 710 may be reduced tothe second thickness T₂ (FIG. 7C). The corrodible material 710 with thesecond thickness T₂ may be less resistant to curving compared to thecorrodible material 710 with the first thickness T₁, due to a loss ofmass and physical structure. Due to the increased curvature of thecorrodible material 710, an interior surface of the corrodible material710 may be positioned a second distance L₂ closer to the distal end 704of the at least one optical fiber 706 compared to the first distance L₁.The change in curvature of the corrodible material 710 may affect alight signal transmitted through the at least one optical fiber 706.Thus, changes in the light signal may be measured and analyzed todetermine corrosion of the corrodible material 710, such as by ananalysis module 116 (FIG. 1) (in the form of, e.g., an interferometer, alight wavelength sensor, a light intensity sensor).

Accordingly, the fiber optic sensor 700 may be used to determine acorrosion rate and/or corrosion amount of the corrodible material 710.In turn, the corrosion of the corrodible material 710 may be correlatedto corrosion of a downhole component, as described above.

Referring to FIGS. 8A and 8B, in some embodiments, a fiber optic sensor800 for wellbore sensing systems of the present disclosure may include aFabry-Perot cavity 802 at a distal end 804 of a plurality of opticalfibers 806. The Fabry-Perot cavity 802 may be defined by a tube 808capped with a corrodible material 810 having an external surface 812that is configured for exposure to a corrosive environment, such as afluid environment of oil and gas exploration or production (e.g., withina subterranean borehole). The fiber optic sensor 800 of FIGS. 8A and 8Bmay generally be configured and operate similar to the fiber opticsensor 700 of FIGS. 7A-7C. However, the plurality of optical fibers 806may enable simultaneous or sequential measurement of multiple portionsof the corrodible material 810.

For example, each optical fiber of the plurality of optical fibers 806(FIG. 8A) may be used to measure corrosion at a unique region 814 (FIG.8B) of the external surface 812 of the corrodible material 810. Thus, inaddition to being used to measure overall corrosion, the fiber opticsensor 800 including a plurality of optical fibers 806 may be used tomeasure non-uniform corrosion, such as pitting, localized corrosion, andcorrosion gradients.

Referring to FIG. 9, wellbore sensing systems of the present disclosuremay include a fiber optic sensor 900 including a Fabry-Perot cavity 902at a distal end 904 of at least one optical fiber 906. The Fabry-Perotcavity 902 may be defined by a first tube 908 capped with an inertdiaphragm 910. A second tube 912 may be coupled to the first tube 908.The second tube 912 may define a cavity 914 between the inert diaphragm910 and a corrodible diaphragm 916. The cavity 914 defined by the secondtube 912 may be filled with an inert fluid 918, such as a liquid (e.g.,oil) or a gas.

The inert diaphragm 910 of the fiber optic sensor 900 of FIG. 9 may notbe a same or similar material to a downhole component. By way of exampleand not limitation, the inert diaphragm 910 may include one or more of aceramic material, a diamond-like carbon (“DLC”) material, an oxidematerial, a sapphire material, an alumina material, and a siliconcarbide material. The corrodible diaphragm 916 may be or include amaterial that is similar to or the same as a downhole component. Forexample, the corrodible diaphragm 916 may include one or more of acarbon steel, a tool steel, a stainless steel, and a so-called“corrosion resistant alloy” (i.e., a mixture of various metals, such asstainless steel, chrome, nickel, iron, copper, cobalt, molybdenum,tungsten, and/or titanium).

The fiber optic sensor 900 of FIG. 9 may operate similarly to the fiberoptic sensor 700 of FIGS. 7A-7C, except that the inert diaphragm 910defining the Fabry-Perot cavity 902 and capping the first tube 908 maynot be corroded during use. Rather, the corrodible diaphragm 916 of thesecond tube 912 may be corroded during use, which may increase apressure on the inert fluid 918, which, in turn, may increase pressureon the inert diaphragm 910 and result in the inert diaphragm 910 curvingtoward the distal end 904 of the at least one optical fiber 906. Thecurvature of the inert diaphragm 910 may be measured, and the curvaturemay be correlated to corrosion of the corrodible diaphragm 916 andfurther correlated to corrosion of a downhole component. Thus, the fiberoptic sensor 900 may be used to sense corrosion without consumption ofthe inert diaphragm 910 defining the Fabry-Perot cavity 902.

Referring to FIGS. 10A and 10B, wellbore sensing systems of the presentdisclosure may include a fiber optic sensor 1000 including a pluralityof optical fibers 1002 having respective distal ends 1004. Optionally,the distal ends 1004 of the plurality of optical fibers 1002 may becoupled to (e.g., disposed within) a transparent material 1006 (e.g., anepoxy material). A sensor material 1008 may be disposed over orproximate to the distal ends 1004 of the plurality of optical fibers1002, such as on a surface of the transparent material 1006 opposite theplurality of optical fibers 1002. The sensor material 1008 may be acorrodible material that is the same as material of a downholecomponent, such that corrosion of the sensor material 1008 may becorrelated to corrosion of the downhole component. Optionally, in someembodiments, a mask material 1010 (as shown by dashed line) including atleast one aperture 1012 therethrough may cover at least a portion of thesensor material 1008.

Fabry-Perot interferometry for measuring corrosion has been generallydescribed in U.S. patent application Ser. No. 08/194,294 to Sirkis,titled “FIBER OPTIC STRESS-CORROSION SENSORY AND SYSTEM,” filed Feb. 9,1994, now U.S. Pat. No. 5,367,583 (“the '583 Patent”), the entiredisclosure of which is incorporated herein by reference. The fiber opticsensor 1000 may operate on the principle that a thickness of thin filmsmay affect a reflectance of the thin film, as discussed in the '583Patent incorporated by reference above. Accordingly, corrosion of thesensor material 1008 may result in a change in reflectance of the sensormaterial 1008 that can be measured using the plurality of optical fibers1002. Alternatively or additionally, the fiber optic sensor 1000 mayoperate on a principle that a change in the thickness of the sensormaterial 1008 results in a change in a distance between the sensormaterial 1008 and the distal ends 1004 of the plurality of opticalfibers 1002, as discussed above in relation to FIGS. 7A through 7C.Accordingly, corrosion of the sensor material 1008 may result in achange in the interference pattern that can be measured using theplurality of optical fibers 1002. In some embodiments, an entire surfaceof the sensor material 1008 may be exposed to a corrosive environment,and the optical fibers 1002 may be used to sense a change in thicknessof respective regions 1014 of the sensor material 1008. In suchembodiments, the plurality of optical fibers 1002 may be used to senseuniform and non-uniform corrosion (e.g., pitting, localized corrosion,corrosion gradients) at the respective regions 1014 of the sensormaterial 1008.

In some embodiments, the sensor material 1008 may have a variablethickness such that each of the regions 1014 of the sensor material 1008has a different thickness than other regions 1014. Initially, a firstone of the regions 1014 may have a thickness that is at or below athickness that renders a reflectance of the first region 1014 sensitiveto a reduction in thickness of the sensor material 1008 at the firstregion 1014. A second region 1014 may have an initial thickness that istwice the initial thickness of the first region 1014. Accordingly, asboth of the first and second regions 1014 corrode, the first region 1014may corrode entirely away as the second region 1014 reaches a thicknessfor which reflectivity is sensitive to additional corrosion. A thirdregion 1014 may have an initial thickness that is three times theinitial thickness of the first region 1014, such that as the secondregion 1014 corrodes entirely away, the third region 1014 reaches athickness for which reflectivity is sensitive to yet additionalcorrosion. Other regions 1014 may similarly have unique thicknesses. Byway of example and not limitation, the first region 1014 may have aninitial thickness of about 5 μm, the second region 1014 may have aninitial thickness of about 10 μm, the third region 1014 may have aninitial thickness of about 15 μm, etc. In such embodiments, the fiberoptic sensor 1000 may be used for a greater period of time and afterfurther corrosion compared to a similar sensor that has a uniformthickness.

Although embodiments of the fiber optic sensor 1000 have been describedas including a single, common sensor material 1008 that is sensed by theplurality of optical fibers 1002, the present disclosure is not solimited. Alternatively, a separate sensor material 1008 may be disposedon a distal end 1004 of each optical fiber of the plurality of opticalfibers 1002. Each of the separate sensor materials 1008 may have adifferent thickness, similar to the different thicknesses of the regions1014 described above. By way of another example and not limitation, eachof the separate sensor materials 1008 may have an initial thickness thatis about 5 μm or less.

In some embodiments, the mask material 1010 may be used to cover one ormore of the regions 1014 of the sensor material 1008 and protect the oneor more of the regions 1014 from corrosion. The aperture 1012 may beused to expose at least one of the regions 1014 to a corrosiveenvironment. An optical fiber 1002 associated with the exposed region1014 may be used to measure corrosion of the sensor material 1008. Afterthe sensor material 1008 at the exposed region 1014 is at leastpartially consumed by the corrosion, the mask material 1010 may berotated or otherwise moved relative to the sensor material 1008 toexpose another region 1014. Then, another optical fiber 1002 associatedwith the exposed other region 1014 may be used to measure corrosion ofthe sensor material 1008. This process may be repeated until all of theregions 1014 are exposed and at least partially consumed by corrosion.In such embodiments, the sensor 1000 may be used for a greater period oftime and after further corrosion compared to a similar sensor that lacksthe mask material 1010. A mask material 1010 as described may also beused with other embodiments that include a plurality of optical fibers,such as with the embodiment shown and described in connection with FIGS.8A and 8B.

In some embodiments, the present disclosure includes wellbore sensingsystems that include multiple fiber optic sensors and, optionally, atleast one reference sensor. For example, multiple fiber optic sensors200 like that described with reference to FIG. 2 may be used together,with each fiber optic sensor 200 including a mass of sensor material 208different from other fiber optic sensors 200. Thus, a first fiber opticsensor 200 may include a first mass of sensor material 208 that includesa first corrodible material and a second fiber optic sensor 200 mayinclude a second mass of sensor material that includes a secondcorrodible material different from the first corrodible material.Alternatively or additionally, a third fiber optic sensor 200 mayinclude a third mass of sensor material 208 that includes an inertmaterial that is susceptible to scale deposition. One or more referencefiber optic sensors 300, as described above with reference to FIG. 3,may be used in combination with the multiple fiber optic sensors.

Similarly, other embodiments of sensors and systems described above maybe combined in various ways to provide a wellbore sensing system forsensing one or multiple conditions within a wellbore. Such a system mayinclude multiple sensors selected from the following list, for example:one or more fiber optic sensors 200, one or more reference fiber opticsensors 300, one or more multi-point sensors 400, one or more referenceoptical fibers 602, one or more fiber optic sensors 700, one or morefiber optic sensors 800, one or more fiber optic sensors 900, and one ormore fiber optic sensors 1000 (described above with reference to FIGS. 2through 10B).

Additional non-limiting example embodiments of the present disclosureare set forth below.

Embodiment 1: A wellbore sensing system, comprising: a tube defining aFabry-Perot cavity; an optical fiber comprising a distal end disposedwithin the Fabry-Perot cavity and a proximal end opposite the distalend; a corrodible material capping the Fabry-Perot cavity; and ananalysis module operatively coupled to the proximal end of the opticalfiber, the analysis module configured to sense and analyze a differenceof a light signal resulting from a change in a distance between thecorrodible material and the distal end of the optical fiber due to achange in thickness of the corrodible material.

Embodiment 2: The system of Embodiment 1, wherein the tube is positionedproximate a downhole component within a wellbore.

Embodiment 3: The system of Embodiment 1 or Embodiment 2, wherein thedistal end of the optical fiber is mounted to an electrical submersiblepump.

Embodiment 4: The system of any one of Embodiments 1 through 3, whereinthe corrodible material is selected from the group consisting ofaluminum, titanium, a carbon steel, a tool steel, a stainless steel, anda corrosion resistant alloy.

Embodiment 5: The system of any one of Embodiments 1 through 4, furthercomprising a reference sensor including a distal end free of thecorrodible material.

Embodiment 6: The system of Embodiment 5, wherein the reference sensorcomprises: another tube defining another Fabry-Perot cavity; at leastone other optical fiber comprising a distal end disposed within theanother Fabry-Perot cavity; and an inert material capping the anotherFabry-Perot cavity.

Embodiment 7: The system of Embodiment 6, wherein the inert materialcapping the Fabry-Perot cavity of the reference sensor comprises one ormore of a ceramic material, a diamond-like carbon material, an oxidematerial, a sapphire material, an alumina material, a silicon carbidematerial, a silicon material, and a metallic material coated with theinert material.

Embodiment 8: The system of any one of Embodiments 1 through 7, whereinthe analysis module further comprises a light source, a photodetectionand signal processing interferometer coupled to a proximal end of theplurality of optical fibers and an output configured to provide a signalcorresponding to a corrosion rate of the corrodible material.

Embodiment 9: A device for sensing corrosion of downhole equipment, thedevice comprising: at least one optical fiber comprising a distal endand a proximal end; a corrodible material disposed over the distal endof the at least one optical fiber; and an analysis module operativelycoupled to the proximal end of the at least one optical fiber, theanalysis module configured to sense and analyze differences in a lightsignal reflecting from the corrodible material.

Embodiment 10: The device of Embodiment 9, wherein the at least oneoptical fiber comprises a plurality of optical fibers, wherein aseparate corrodible material is disposed over a respective distal end ofeach optical fiber of the plurality of optical fibers, wherein each ofthe separate corrodible materials comprises a different thickness fromother separate corrodible materials.

Embodiment 11: The device of Embodiment 10, wherein an initial thicknessof each of the separate corrodible materials is about 5 μm or less.

Embodiment 12: The device of any one of Embodiments 9 through 11,wherein the analysis module comprises at least one of an interferometer,a light intensity sensor, and a light wavelength sensor.

Embodiment 13: The device of any one of Embodiments 9 through 12,wherein the distal end of the at least one optical fiber is disposedwithin a transparent epoxy material, wherein the corrodible materialcoats a surface of the transparent epoxy material, further comprising amask with an aperture therethrough, the mask covering the corrodiblematerial, the mask and aperture configured to selectively expose aregion of the corrodible material corresponding to the at least oneoptical fiber.

Embodiment 14: A system for sensing at least one condition in oil andgas exploration or production equipment, the system comprising: at leastone optical fiber comprising a distal end, at least one fiber Bragggrating proximate the distal end, and a proximal end; an analysis moduleoperatively coupled to the proximal end of the at least one opticalfiber, the analysis module configured to sense and analyze variations inlight reflected from the at least one fiber Bragg grating; and a mass ofsensor material coupled to the distal end of the at least one opticalfiber, at least one surface of the mass of sensor material exposed to anenvironment surrounding the distal end of the at least one opticalfiber, wherein the distal end of the at least one optical fiber with themass of sensor material coupled thereto is suspended from above the atleast one fiber Bragg grating to induce stress on the at least one fiberBragg grating due to a weight of the mass of sensor material.

Embodiment 15: The system of Embodiment 14, wherein the mass of sensormaterial consists essentially of a mass of corrodible material.

Embodiment 16: The system of Embodiments 14 or Embodiment 15, furthercomprising at least one reference optical fiber comprising a distal endincluding a fiber Bragg grating and a mass of inert material coupled tothe distal end of the at least one reference optical fiber.

Embodiment 17: The system of Embodiment 16, wherein the distal end ofthe at least one reference optical fiber is positioned adjacent to thedistal end of the at least one optical fiber.

Embodiment 18: The system of Embodiment 16 or Embodiment 17, wherein themass of inert material comprises at least one of a ceramic material, adiamond-like carbon material, an oxide material, a sapphire material, analumina material, a silicon carbide material, a silicon material, and amass of metallic material coated with the inert material.

Embodiment 19: The system of any one of Embodiments 14 through 18,wherein the mass of sensor material is selected to be at leastsubstantially the same as a material of a surface of a downholecomponent to be exposed to a same environmental condition as the mass ofsensor material during disposition of the mass of sensor material andthe downhole component in a wellbore.

Embodiment 20: The system of any one of Embodiments 14 through 19,further comprising a housing covering lateral sides of the mass ofsensor material.

Embodiment 21: The system of Embodiment 20, wherein the housing iscoupled to a downhole component.

Embodiment 22: The system of any one of Embodiments 14 through 21,further comprising a substrate of inert material coupled to the at leastone optical fiber proximate the distal end of the at least one opticalfiber, wherein the mass of corrodible material is coupled to thesubstrate.

Embodiment 23: The system of any one of Embodiments 14 through 22,wherein the at least one optical fiber comprises a plurality of opticalfibers each comprising a distal end including a fiber Bragg grating andeach coupled to the mass of corrodible material.

Embodiment 24: A device for sensing deposition of material on downholeequipment, the device comprising: at least one optical fiber comprisinga proximal end and a distal end including a fiber Bragg grating; ananalysis module operatively coupled to the proximal end of the at leastone optical fiber, the analysis module configured to sense and analyzevariations in light reflected from the at least one fiber Bragg grating;a suspension element coupled to the at least one optical fiber above thefiber Bragg grating; and a mass of inert material coupled to the atleast one optical fiber below the fiber Bragg grating and suspended fromthe suspension element by the distal end of the at least one opticalfiber.

Embodiment 25: The device of Embodiment 24, further comprising: at leastone reference optical fiber comprising a distal end including a fiberBragg grating; and a mass of material coupled to the at least onereference optical fiber proximate the distal end of the at least onereference optical fiber, at least an exposed portion of the mass ofmaterial being selected to resist deposition of scale thereon.

Embodiment 26: A system for sensing at least one condition in asubterranean wellbore, the system comprising: at least one optical fibercomprising a distal end, a plurality of fiber Bragg gratings along alength thereof, and a proximal end; a plurality of sensor materialscoupled to the at least one optical fiber and surrounding respectivefiber Bragg gratings of the plurality of fiber Bragg gratings; and alight wavelength sensor coupled to a proximal end of the at least oneoptical fiber, the light wavelength sensor configured to sense awavelength of light reflected from the plurality of fiber Bragggratings.

Embodiment 27: The system of Embodiment 26, wherein the plurality ofsensor materials comprises a material selected to react with a reactivechemical.

Embodiment 28: The system of Embodiment 27, wherein the reactivechemical comprises H₂S.

Embodiment 29: The system of Embodiment 27 or Embodiment 28, wherein thematerial selected to react with a reactive chemical comprises a metaloxide material.

Embodiment 30: The system of any one of Embodiments 27 through 29,wherein the material selected to react with a reactive chemicalcomprises ZnO.

Embodiment 31: The system of Embodiment 26, wherein the plurality ofsensor materials comprises a pre-stressed corrodible material.

Embodiment 32: The system of any one of Embodiments 26 through 31,further comprising at least one reference optical fiber extending alongthe length of the at least one optical fiber.

Embodiment 33: The system of any one of Embodiments 26 through 32,wherein the plurality of fiber Bragg gratings is spaced along the lengthof the at least one optical fiber at intervals of at least about 5 mm.

Embodiment 34: A wellbore sensing system, comprising: a first device forsensing corrosion of downhole equipment according to Embodiment 9 andcomprising a first corrodible material disposed over the distal end ofat least one first optical fiber; and a second device for sensingcorrosion of downhole equipment according to Embodiment 9 and comprisinga second corrodible material different from the first corrodiblematerial disposed over a distal end of at least one second opticalfiber.

Embodiment 35: The system of any one of Embodiments 1 through 8, furthercomprising at least one additional optical fiber comprising a distal enddisposed within the Fabry-Perot cavity, wherein a separate corrodiblematerial is disposed over a respective distal end of each of the opticalfiber and the at least one additional optical fiber, wherein each of theseparate corrodible materials comprises a different thickness from otherseparate corrodible materials.

Embodiment 36: The system of any one of Embodiments 1 through 8, furthercomprising: at least one additional optical fiber comprising a distalend disposed within the Fabry-Perot cavity; and a mask with an aperturetherethrough, the mask covering the corrodible material, the mask andaperture configured to selectively expose respective regions of thecorrodible material corresponding to the optical fiber and the at leastone additional optical fiber.

The embodiments of the disclosure described above and illustrated in theaccompanying drawing figures do not limit the scope of the invention,since these embodiments are merely examples of embodiments of thedisclosure. The invention is encompassed by the appended claims andtheir legal equivalents. Any equivalent embodiments lie within the scopeof this disclosure. Indeed, various modifications of the presentdisclosure, in addition to those shown and described herein, such asother combinations and modifications of the elements described, willbecome apparent to those of ordinary skill in the art from thedescription. Such embodiments, combinations, and modifications also fallwithin the scope of the appended claims and their legal equivalents.

1. A system for sensing at least one condition proximate the system, thesystem comprising: at least one optical fiber comprising a distal end, aplurality of fiber Bragg gratings along a length thereof, and a proximalend; a plurality of sensor materials coupled to the at least one opticalfiber and surrounding respective fiber Bragg gratings of the pluralityof fiber Bragg gratings; and a light wavelength sensor coupled to aproximal end of the at least one optical fiber, the light wavelengthsensor configured to sense a wavelength of light reflected from theplurality of fiber Bragg gratings.
 2. The system of claim 1, wherein theplurality of sensor materials comprises a material selected to reactwith a reactive chemical.
 3. The system of claim 2, wherein the reactivechemical comprises H₂S.
 4. The system of claim 2, wherein the materialselected to react with a reactive chemical comprises a metal oxidematerial.
 5. The system of claim 2, wherein the material selected toreact with a reactive chemical comprises ZnO.
 6. The system of claim 1,wherein the plurality of sensor materials comprises a pre-stressedcorrodible material.
 7. The system of claim 1, further comprising atleast one reference optical fiber extending along the length of the atleast one optical fiber.
 8. The system of claim 1, wherein the pluralityof fiber Bragg gratings are spaced along the length of the at least oneoptical fiber at intervals of at least about 5 mm.
 9. The system ofclaim 1, wherein at least one sensor material of the plurality of sensormaterials comprises a pre-stressed corrodible material that causes arespective fiber Bragg grating around which the at least one sensormaterial is disposed to be in axial tension or compression.
 10. Thesystem of claim 1, wherein the plurality of fiber Bragg gratings arespaced along the length of the at least one optical fiber at intervalsbetween about 5 mm and about 2 cm.
 11. The system of claim 1, whereinthe system is configured to determine one or more of a temperature, apressure, a presence of reactive chemicals, and a corrosion rateproximate the plurality of sensor materials.
 12. The system of claim 1,wherein each sensor of the plurality of sensor materials issubstantially the same.
 13. The system of claim 1, wherein a diameter ofthe sensor materials of the plurality of sensor materials is larger thana diameter of the at least one optical fiber.
 14. The system of claim 1,further comprising at least one reference optical fiber extending alongthe length of the at least one optical fiber, the at least one referenceoptical fiber including a plurality of inert materials disposed aroundthe at least one reference optical fiber.
 15. The system of claim 14,wherein the plurality of inert materials are disposed around fiber Bragggratings of the at least one reference optical fiber.
 16. The system ofclaim 14, wherein the plurality of inert materials comprises one or moreof a ceramic material, a diamond-like carbon material, an oxidematerial, a sapphire material, an alumina material, a silicon carbidematerial, or a silicon material.
 17. The system of claim 1, wherein thelight wavelength sensor is configured to isolate portions of signalsfrom the plurality of sensor materials of the at least one optical fiberresulting from the at least one condition based on signals from the atleast one reference optical fiber.
 18. The system of claim 1, whereinthe plurality of sensor materials comprises a metal oxide.
 19. Thesystem of claim 1, wherein the light wavelength sensor is configured toindependently sense a wavelength of light reflected from each of theplurality of sensors.
 20. The system of claim 1, further comprising acladding material around the at least one optical fiber and adjacent tothe plurality of sensor materials.